Good morning, my name is Seles [ph], and I will be your conference operator today. At this time I would like to welcome everyone to the fourth quarter and year-end 2010 earnings release and operations update for Oasis Petroleum. All lines have been placed on mute to prevent any background noise. After the speakers remarks there will be a question-and-answer session. (Operator instructions) I would now like to turn today’s call over to Mr. Lou. Sir, you may begin you conference.

Thank you Seles. Good morning everybody. This is Michael Lou, Senior Vice President of Finance. We’re reporting our fourth quarter and year ending December 31, 2010 results today, and we’re going to have you join our call. With me today from Oasis, are Tommy Nusz, President and Chief Executive Officer; Taylor Reid, Chief Operating Officer; Roy Mace, Chief Accounting Officer; and Richard Robuck, Director of Investor Relations. This conference call is being recorded, and will be available for replay approximately one hour after its completion. The conference call replay and our earnings release are available on our website at www.oasispetroleum.com. In addition, we have updated our investor presentation for the latest financial and operational results, which is on our website. Although we will not be speaking off the slides during this call, please feel free to refer to it for clarification. Please be advised that our following remarks, including the answers to your questions, include statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently anticipated. Those risks include among others, matters that we have described in our earnings release, as well as in our filings with the Securities and Exchange Commission, including our Form S-1 and as amended. We disclaim any obligation to update these forward-looking statements. Please note that our 2010 Form 10-K will be filed tomorrow. During this conference call we will also make references to adjusted EBITDA, which is a non-GAAP financial measure. Reconciliations of adjusted EBITDA to the applicable GAAP measures can be found in our earnings release or on our website. I will turn the call over to Tommy.

Good morning everyone, and thanks Michael. First I would like to thank everyone for joining us this morning. I think it is fair to say that we have plenty to celebrate here at Oasis, as it relates to the year 2010, as we ended the year with very impressive results, including a successful IPO. I’m very proud of the team that we put together, and what we have been able to accomplish. I’m also confident that they are ready to take on the challenges ahead in 2011, as we continue to increase activity and focus on the drivers of value. We have had much of our year-end data now for over a month, and as you know, we don’t see much need in reading our press releases to you. So we will try to focus this call on the high points for 2010, and the outlook for 2011. I will cover operations first, and will let Michael finish up with our financial conversation. We set out at the beginning of 2010 to establish our drilling program in the Williston Basin in order to grow production and reserves. We definitely achieved that and what we set out to do, as we grew from two rigs from the end of 2009 to 6 rigs at the end of 2010. We have another rig showing up in the Williston around the end of this month, which will give us 6 rigs in the West and one rig in the east. We grew production to 7511 Boes in the fourth quarter and ended the year with reserves of 39.8 MMBoes. We also completed two strategic bolt on acquisitions in Montana that we are very excited about, and we will give you some more color on what we are seeing in this area, which we…

Thanks Tommy. On the financial front, we are drilling nothing that you haven’t already heard from us. When we reported reserves and updated operational ranges for 2010 in January, and our actuals are right in line with what we said they would be. On the heels of the January operational update, we raised 4 million of debt, which will give us on a pro forma basis just over $530 million of cash and $670 of overall liquidity as of December 31, 2010. We expect our current liquidity will fund all of 2011 CapEx, and well into if not completely through our 2012 capital program. For the full year 2010, we had a realized prices $69.50 per barrel, and differentials of approximately 13%. Differential GAAP to over 14% in the fourth quarter, primarily due to the Enbridge six day line and its impact to October differentials. We believe differentials in 2011 will be on average in the 12% to 15% range. Given the current price environment and our aggressive drilling program we are putting in additional financial hedges like Tommy said, and we continue to evaluate and add real deals on gross operated volumes in order to protect against some of the downside commodity risk. Concerning rail, you may have seen the latest presentation on the North Dakota pipeline authority website, which has slides from the February 28 North Dakota’s crude oil rail transportation infrastructure web cast. It had some information about the plans and capacity for rail coming out of North Dakota. A couple of quick notes before we open the call for questions. LOE picked up from $6.33 per barrel in the third quarter to $7.92 per Boe in the fourth quarter. This was really just making sure that we are fully accrued for operating expenses. We continue to see LOE decrease in 2011, down into the $5 to $7 per Boe range. G&A ended up in the range that we expected, and Q4 was higher than Q3 primarily due to the fact that our full year bonus was accrued in December, instead of being accrued across all four quarters of the year. We talked about this on the November call, and we have decided to accrue bonuses throughout the year if warranted from now on. Also we had a successful 2010, with more than double production, we almost tripled reserves and adjusted EBITDA was up almost 5 times to $82.2 million. We have a strong balance sheet with plenty of cash to invest into our greater than 20-year drilling inventory, which would drive growth and shareholder value. With that I will turn the call back over to Seles to open the lines up for questions.

(Operator instructions) Your first question comes from the line of David Kistler with Simmons & Company. David Kistler – Simmons & Company: Good morning guys.

Good morning Dave. David Kistler – Simmons & Company: Real quickly on the 18 wells that are drilled and waiting on completion, you mentioned that weather is the primary component there, has access to services been a challenge, and you talk about adding an additional frac crew, will that alleviate that challenge, or do you think about maybe even looking at vertical integration like some other folks have spoken about?

Dave, what I would tell you is that the build in the backlog is really a function of the weather that we experienced, and it is always difficult fracing wells in the winter, but this year was particularly brutal. So I think the build in the backlog was largely around the weather. And then with respect to additional crews or additional pumping services, we are looking at a lot of things, and as I mentioned we have got a lot of interesting alternatives to consider. It looks like we will have another dedicated crew here in the next couple of months, and once that comes on we will really be able to start working that inventory off, that backlog off and especially given that we will be doing it as we go into some better weather than what we’ve experienced in the first quarter. So, we are always going to have a bit of a backlog, which I think is fine, call it 8 to 10 wells. But it is a little bit higher than what we like, but again primarily weather driven. David Kistler – Simmons & Company: That is helpful. Just maybe for clarification, if the weather hadn’t been an issue, what does the first production kind of times look like, because they – in the past you talked about just under 90 days, or are we getting more efficient on that end as well?

Yes, hard to say because I think that is a good normalized run rate. Obviously with the backlog it is going to grow a bit. David Kistler – Simmons & Company: Okay. That is helpful.

At least in the near term Dave. Ultimately, I think, we ultimately normalize frac to 90, until we get to the point where we’re really in full blown pad and pattern drilling, where we can start to really drive that down meaningfully? David Kistler – Simmons & Company: Okay. That is helpful. And then one question just on reserves, when we look at the approved reserves, can you talk about the spending plan that matches up with that, is that a plan that is essentially within discretionary cash flow, outside of discretionary cash flow over the five-year period?

Yes, I think Taylor has got that.

So, you are talking about capital for our PEDs? David Kistler – Simmons & Company: Exactly.

Total capital for all of our booked PEDs are just under 350 million. When you look in gross well account, it is 124 net wells, 53 [ph]. So when you look at cash flow over the 5 year period with that plan, it still is in line with our cash on the balance sheet, plus our cash flow, you have plenty of capital executing those plans, well below what we are going to spend.

So, if you look at that just notionally without dragging through CapEx, so that will be about $70 million a year, and EBITDAX for last year was 82 million. If you would use our fourth quarter run rate, it will be about 120. So it is clearly covered. David Kistler – Simmons & Company: Great. Thanks for clarification. Very helpful. I will let somebody else jump on guys.

Thanks.

Your next question comes from the line of Ron Mills with Johnson Rice.

Good morning Ron. Ron Mills – Johnson Rice: A couple of questions. You did a good job of walking through your individual areas, first West Williston and East Nesson, as you look at your Montana acreage, and the Hebron acquisition, what type of activity levels do you see in that area, and then the 400,000 to 700,000 barrels that you have used for West Williston is that also being applied to the Montana acreage as well?

Yes, Ron. In essence it is about 14% of our CapEx. As we talk about one rig programs typically will consume about $50 million per year, and we expect to run one rig over there. So I think our actual CapEx is around 60. So it is a little bit higher than that with some other things that we are doing, but that is a good way to think about it. We will continue to at least, you know, for the foreseeable future through this year continue to run one rig and that is sufficient to help us protect our position there. As we have mentioned with the 400,000 to 700,000 type curve range, early days, but it looks like the existing wells there are producing within that range, with 23 stages, and so when you start thinking about adding incremental stages, even just getting up to what we normally do 28, than we think that that range is pretty solid. Ron Mills – Johnson Rice: And then that leads into the second question, you know you experimented or you utilized a 28 stage process through most of last year. You know, if you look across your different project areas, do you think it will be pretty universal that you can utilize 36 stage fracs in even the Montana, and early days since you are really starting to really test the Three Forks. But a similar process in Three Forks, should we also march up along that frac stage curve.

What I would say about that Ron is that I think that in the Middle Bakken I think we will clearly be transitioning to 36. Even the Ernst well that we did overall in the east side and East Nesson remember was I think 25, 24 stages and 11 sleeves [ph], or something. It may not be exact, but it is close to that. So, I think you will see us transition there on the Middle Bakken. With respect to the Three Forks, we don’t have enough history to be confident about that linear relationship between stages and recoveries like we do in the Middle Bakken, because we just have so much more data. So we just, again we need to approach it from one direction as we think about the Three Forks. Ron Mills – Johnson Rice: Okay, great. And then lastly, just on the infrastructure, you mentioned whether it is yourselves or third parties building out infrastructure, what is the timeline of that. I’m assuming you are talking about both clean and dirty water, and gas lines being put in relative to your development plan?

Yes, Taylor you want to pick that up?

The gas infrastructure on the west side to Indian Hills, Red Bank and Hebron should be hooked in, and wells producing by third quarter. The infrastructure for saltwater disposal, we have got ongoing projects in Red Bank with two wells currently operating, and then we’re doing additional work in Indian Hills, Hebron and overall in the east side and all of that should be up and running by the fourth quarter. Ron Mills – Johnson Rice: And is that one of the things that will then drive that LOE down as we move through the course of the year?

Correct, as Tommy said, to haul water it is about $2.50 to $3 a barrel, when we get our systems in place, you will test the cost under $1 a barrel. So it will drive down LOE. Ron Mills – Johnson Rice: Great. All right guys, let me let someone else jump in. Thank you.

Thanks Ron.

Your next question comes from the line of Oliver Doolin with Tudor, Pickering, Holt.

Good morning guys. Just wondering, could you comment, just some of your competitors have hedged production based on estimated production going forward, just wondering how do you see that, is that a possibility for you, and kind of what are the things you look at when you look at hedging?

I will let Michael that one up.

Sure Oliver, right now we have got 7000 barrels a day hedged in 2011. We have got mainly collars, and three way collars, and then you heard Tommy talk about we are putting in more each stage is kind of layering them on. More recently we have been focused on between $80 and $95 floor levels just given the run-up in the oil price. If you think about it from a couple of standpoints, if you look at it compared to the fourth quarter, we are basically for 2011 at our fourth quarter levels. If you look at compared to our expected range for this year, we’re just north of 50%. 2012 we have got 5500 barrels a day hedged right now, and we have got about 2000 barrels a day in 2013. We will continue to layer on more given that we know the expected production will likely be much higher than those levels. We will just continue to layer that on over time.

Okay, great. Thanks, and then just my last question will be something along the lines of, can you comment on the amount of Three Forks wells versus Bakken wells you plan to drill this year, either qualitatively or preferably quantitatively?

We have got 59 total gross operated. Of those roughly 5 Three Folks wells.

Great. Thank you. That is all I had.

Great. Thanks.

Your next question comes from the line of Derek Whitfield with Canaccord Genuity. Derek Whitfield – Canaccord Genuity: Good morning guys.

Good morning Derek. Derek Whitfield – Canaccord Genuity: High-level question for you, and thinking about your current liquidity and development plans, I’m interested in your thoughts on accelerating development beyond the current program, and maybe more specifically outside of services, are there any other organizational objectives you are hoping to check off before pursuing a more aggressive development program?

What I would say is that as we have talked about, first phase for us is working through additional stages. We are looking at pressure pumping services as kind of being the driver to pace as I alluded to earlier. But we have got – as we have always talked about, we want to make sure that we have got enough pressure pumping services that support rigs that we bring on. We don’t want to drill a bunch of wells we can’t complete. So like a lot of things, we will try to approach it from one direction, not inconceivable to think that with some of that have two full time crews up and running that towards the end of the year we could pick up another rig, and then see where it goes from there. Organizationally, we have grown from May we were roughly 30 people pre-IPO full time. Now it has been over 60. And so for the guys have spend a lot of time on it as you can imagine doubling the headcount in six months. But I think within what is reasonable to expect given the service infrastructure and timing that we can fill slots that we need to accommodate that on the manpower side. Derek Whitfield – Canaccord Genuity: Got it. That makes sense. And then, can you comment on the preliminary data you are receiving from drilling operations on the Williston and More Three Forks well, and then perhaps more specifically is there anything you are seeing in the geology that encourages you to go after the Three Forks objective versus the Bakken?

So, the Williston and the More wells are consistent with what we saw in drilling the horizontals with the vertical penetrations in the area. So we just got to have to see how they perform when we test the wells. Three fourths relative to the Bakken, we just don’t have enough tests on the west side, really across all of our acreage position to tell you how the Three Forks will perform relative to the Bakken. And so, as we get to the end of this year, and we have got 5 wells we have been talking about testing, we’re going to have a much better indication of relative performance. Derek Whitfield – Canaccord Genuity: That is very helpful, and then one final question. What are your latest thoughts on marketing arrangements given the recent spread between WTI and LLS [ph]?

Clearly there is a disparity there, and I think like a lot of other guys in the basin, we are looking at options to be able to get our oil to different markets. There are some real options to get to LLS change, and so we’re looking at all of those things. Most of our oil right now is marketed through third parties, and we end up with being in-depth either off of WTI, or Clearbrook for the most part. So we don’t yet have a lot of closure to LSS, but something we are looking at.

The other thing to keep in mind is that that differential in the WTI to LLS differential has run up pretty good in the last few months. But just given the timing, now the run up is pretty volatile. So what you don’t want to do is run out and spend a whole lot of capital to resolve something that is a short-term blip, if that's the way it turns out. Derek Whitfield – Canaccord Genuity: That is a fair point, but just want to get your color and thoughts on that. That is all from me guys. Thanks.

Perfect. Thanks.

Your next question comes from the line of Steve Berman with Pritchard Capital.

Good morning.

Good morning Steve.

I was wandering if you could touch on any thoughts you might have on density drilling with rig amount talking for Bakken in the three fourths to 12.80. What is your thoughts on that, as far as the Oasis interest in this channel?

Yes, Steve, what I would say is it is still early days, but it certainly looks like that it is a minimum of three and likely four. Fortunately, we will have some good information here over the next 12 months to verify that, but just notionally as you think about it as we’ve talked about before with three wells you get what we estimate based on our subsurface mapping 12% to 15% of original oil in place. So you have to think that more is going to be required to get that ultimate recovery up. Early days on the Three Forks, so, as we talked about we saw (inaudible) say that they are going from two to three. So, we got a fair amount of data though within Sanish. So it looks like it is moving in that direction as well. But it is just too early to kind of throw down a number and say it is absolutely that.

Okay, and if you touched on this I apologize, but any plans on further testing the Burke county acreage, where you drilled the revenue well?

I don’t think that we have got anything in this year’s capital program with the (inaudible). The guidance we are still looking at some of the options for reverse engineering on that as we have talked about before. We probably do have a little bit of lease exposure there, but in the overall scheme of things, it is not significant to our inventory. As you may know that in our last pass inventory we excluded that out, basically now we are calling it more of a contingent area.

Got it. All right. That is it from me. Thanks guys.

Great. Thanks Steve.

Your next question comes from the line of Bob Morris with Citigroup.

Good morning.

Good morning Bob.

When you talked about going from 28 to 36 stage fracs, are you spacing those tighter, or are you now doing laterals that are longer than 10,000 foot?

Outside our spacing, the laterals are still 10,000.

Okay. And did you say that all your Bakken wells this year would be 36 stage?

Yes, the – for sure in Indian Hills and the southern part of East Nesson. Some of the wells are already drilled and already done at 28 stages. So there is only so much we can do obviously, but going forward the majority of them will be 36 stages. Is that fair to say?

In those two areas, and then we continue to test 36 stages with some select wells in Red Bank and we will drill additional wells there with 36 stages this year. Early results are encouraging, so you may see us move that area 36 stages a little later in the year.

And so for those two areas, you are fairly confident at this point that the range of the type curve, you can move those up by 150,000 barrels with the 36?

Yes, on a net basis, I think we can call that roughly 100,000 to 120,000.

Okay. And then when you said your budget reflected $7.5 million per well for – that corresponded to a 24 stage frac. With most of these wells are largely supposed to be in 36 stage, then we need to incorporate a little bit higher well cost on average in the budget than that 7.5 million is that correct?

Yes, when we – typical design has been 7.2 to 7.4, 28 stages. I think you said 23 or 24, but it is in the 28 stages, 55% ceramic, 35% sand. Keep in mind, as others have talked about and we have talked about for a long time, that varies a bit by geographic pod, and now that we have got the wells within the type curve ranges, we play with a lot of things including concentrations per stage, and compositions per stage in some places, we use all white sand, but as we came into the end of last year, the first of this year, we ended that last year really it was what we saw, and actuals was more in the 7 to 7.4. We are thinking what are some of the cost creep on a 28 were more in the 7.5 range, maybe even a little bit higher. But then as we start doing these others with 36 stages and 100,000 stage then that will start to bump the number up and so we will have to – we’re working through all that right now to try to get a feel for impact on a CapEx spend, and it is easy to just apply the number to the well count, but you got to consider timing, timing of stimulation services, once you start doing 36 stages, and what that means to how much capital you spend in the calendar year. So it is simple as it would appear at the surface.

Sure. And then when you talked about the well count, 69, gross operating wells what does that net down to on a net basis?

47.

47, great.

And that is 47 and 6, so the 6 net non-op wells gets the total program to 53. The 69 to 47 on strictly the operating side.

Okay, great. Thank you very much.

Okay Bob.

Your next question comes from the line of Irene Haas with Wunderlich Securities.

Hello everybody. I have a question on Sanish, can you hear me?

Yes.

Okay. Just excited that you guys are starting to drill it, and just wanted to get a sense potentially of how these 5 wells are spread out, and how you feel about the reservoir configuration with the new three fourths, should we expect something probably a little more variable versus what we use in the Middle Bakken, and just a little more color on what is really kind of exciting at the drilling site [ph]?

Yes, at the macro level what I would say is based on what we have seen at least on the west side, with some of the Brigham wells, the data so far would indicate that the Three Forks would be consistent with those type curve bands. You start to move below that, and we will have some more data. You know, this is kind of with the Brigham wells, there is a fair amount of data cut on the east side of our western position. Obviously with these two new wells that straddle the state line right around the Hebron, we will have some really good data there. We had that one Continental Obert well that looks good over on the state line up and the Red Bank block. So, we just need some more data points. Taylor, you want to add anything?

So, we have got actually one well in Indian Hills that is drilled but not yet completed. It is a Three Forks test. A test by another operator has recently been released, only a month reduction, but it looks very encouraging.

And it is right off the south-east corner of our Indian Hills block.

Does it seem better as you approach more (inaudible)?

It is really area dependent. We have done the same thing in the brief work that we have done in the Bakken, which is try to map hydrocarbon floor volume, and ultimately oil in place. So the water saturation is important, as well as thickness and reservoir quality. There is some variability to your question about where will we drill. We got the two in the Hebron area. We will drill one in Red Bank, two in Indian Hills, and one in the southern part of the East Nesson. This year those are the five wells.

Got you. How far does your footprint be from these five wells? How big an area are you planning?

I don’t want to tip how big an area it is.

If you look at, if you just go from the state line where the two wells straddle the state line over to where our well is maybe in Indian Hills. That is roughly 3.5 or 4 townships.

Okay.

I am sorry. Your next question comes from the line of Marty Beskow with Northland Capital.

What are you seeing for opportunities for potentially acreage acquisitions for 2011, and what kind of quality is the acreage that you are seeing, and what type of pricing are you seeing for potential add-ons of acreage?

Yes, so this year, we have got budgeted just for routine land acquisition, about $20 million. We have been able to add acres in and around our blocks depending on the geographic pod anywhere from $400 to $800 an acre without brokerage costs. And you know, it is mostly relatively small parcels that but we have been able to supplement our blocks in that range. Now bigger blocks typically will cost a bit more. You saw that with the Hebron deals that we did at the end of last year.

Are you seeing many potential acquisitions for bigger blocks, of things that you would be interested in?

You know, there continues to be things that pop-up. One of the things that we have to be very careful of is going out and spending a significant amount of dollars on blocks at very high per acre cost when we have got already 300,000 at an average cost of $350 an acre, and there is plenty of inventory to keep us busy.

Okay. And then also, for your G&A outlook for the year, and what is your current guidance for G&A excluding stock based comp considering that it sounds like you will accruing bonus throughout the year?

Yes, Michael…

Yes, our guidance is $6 to $7.50 per Boe. That does include stock based comp.

That does include stock based comps?

It does. That is all in it.

Yes. To keep – Michael, you may want to just on it…there are a couple of different components of clarification with respect to 2010 that positively…

So, we have a line-item that is called stock based comp, and we go through it in detail both in our S1 at the IPO, as well as in the press release that you have seen. Stock based comp under that is actually a bit of an unusual item, where the Oasis Petroleum Management group, or the management of the company has given part of their shares to employees. So it hits our books, but it is non-cash, non-dilutive to shareholders. It is not the same as kind of normal restricted stock grants that might be given by the company. So, there is a component of that that is actually in our G&A. And so when we are guidance to G&A numbers, we are talking with all in with that normal stock based comp that a company would pay.

Okay. All right. Thank you.

Your next question comes from the line of Marshall Carver with Capital One.

We have got – we don’t have any plans to do any type facing tests this year. The focus is really on old acreage, one well per space unit. We will drill two wells in fairly close proximity, and plan to frac both of those wells at the same time in new micro seismic. So, we are trying to get some of that data. It is not quite as high [ph] you might see for example at four wells for space and units that will be close enough to get some of that data.

When do you plan on drilling those two wells?

Those will be completed later this year. We’re not going to partly drill.

Okay. That would be a second half 2011 event.

Yes.

Okay. That’s it from me. Most of my other questions were answered. Thank you.

Great. Thanks Marshall.

Your next question comes from the line of Peter Mahon with Dougherty & Company. Peter Mahon - Dougherty & Company: Yes, good morning guys. Most of my questions have been answered as well, but one thing I did want to ask about is how many of your acreage is there risk for exploration in 2011 and 2012, and where would that acreage be?

Yes, so we will have a detailed table that will be in our 10-K. But for 2011, it is about 54,000 net acres at risk. Anyway, to start with that, and 2012 24,000 net acres. We think in both cases we can preserve all of what we want to with our drilling program. Most of what will be exposed is more in some of the higher water cut areas over on the East Nesson side. It wouldn’t be in our inventory anyway. As we think about conversion to HBP, we have got about 90,000 acres HBP currently. And with our drilling program over the next two years, HBP about 60,000 acres a year. So, as we get into the end of 2012, we are going to be somewhere in the 220 range. So, we are in real good shape. Peter Mahon - Dougherty & Company: Okay, great. Thanks a lot for the color.

You bet. Thank you.

Your next question comes from the line of Dan Mcspirit with BMO Capital.

Gentlemen, good morning.

Good morning Dan.

You mentioned the Mary Wilson and the Wilson wells that have gone – waiting on completion, can you provide any timing on the completion date for those two wells, those are being completed with 28 stages, correct?

Correct. I think the Mary Wilson is currently fracing. I don’t know what the timing is of the Wilson yet, but the Mary Wilson is the Middle Bakken well.

In the second quarter, we don’t have an exact date yet.

Okay. Very good, and then the investments in the saltwater disposal lining system, just roughly what is the capital investment for that?

Total capital for infrastructure for the year is $20 million. Mostly (inaudible) gathering systems, and SWD [ph] wells, but there is some additional capital for electrification and things like that. I don’t have the exact breakout, but most of it…

Got it. Thank you, and then one more if I could, just generally, can you give us a sense of the rate to frac ratio in the Williston Basin today, and how it is trending and how do you expect it to trend over the balance of 2011, is it as high as 7 to 1, or 8 to 1.

I don’t know if I have got the exact ratio, but it is clearly undersupplied right now. Based on the rig count that we have been working at for all operators backlog of completions, if you stay flat on rig, from what we hear come into the basin, the basin might be at balance by the end of the year when rigs continue to pick up, and get more increases it is going to take longer, then as you are adding. If you are going to talk about more intensity of frac stages that pushes it out in time.

Yes, indeed. And then one more lastly here, I’m sure you see your share of property packages, and I’m sure you have got a few on your desk today. Can you share with us any texture of just generally on those property packages, where they are being sourced from, are they more from private companies versus public companies, and if you were to add up the acreage on the same property packages that are again sitting on your desk today, what would they total.

Well, what I would say is that most of the things we are seeing are more privately generated than public. I mean, there are some public things where people are doing clean up or optimization work. You have seen those recently. If you were to add up everything that is floating around in the market today from an acreage basis, I don’t even know if I could make a good wild guess.

It is hundreds and thousands in acres.

Some hundred thousand plus or minus.

Got it. Thank you. All the best. Thanks.

You bet.

Your next question comes from the line of Chitra Sundaram with Cardinal Capital.

Thank you. Congratulations. Great quarter. A couple of things, you talked about the delta, the current CapEx budget kind of 7.5 million, just kind of over 7.5 million, if you have decided to do the additional stages, about 100 K more per stage. So that would be an additional 800,000. So just wanted to get that piece is not currently in the CapEx estimates, and you are not trying to get your arms around what that addition will be? Correct?

Yes, so if you were to take just call it for fun, let’s take 800,000, and we have got 47 net wells. And that is $38 million roughly. Okay. And we already had 16 wells, let us call it 8 or 9 in the budget. So, plus you got to factor in timing. So, I’m doing this off the top of my head, which we why…

Yes.

When we come out with a plan we’re going to tell you, but I would say that it is probably 25ish, maybe a little bit lower 20 million. Taylor.

Yes, that is kind of good.

Yes, probably closer to 15 million when you look at working interest in wells, and not all of them will be 20 – not all of the wells will be…

Correct. We don’t know how many will get done. So, we think it is probably an incremental 15 million at most by the end of the year. We just need to continue to work on it.

Can you help me understand how much of those 53 wells, and I apologize if you have discussed this in the past, how many of those 53 wells that are in the CapEx budget are in the Indian Hills and the Red Bank I think you said area, because those seem to be the most prolific?

So, we have got in – in the Indian Hills there is 17 wells, gross.

Hold on, so you have got net numbers, and he is going to give you gross, and then maybe…

In general, you would use about 65%.

Got it.

For 17 gross wells, about 12 net wells in Indian Hills, and the other area you are asking about was?

I think it is the Red Bank right?

Yes, Red Bank there is 29 gross wells, and that is about 21 wells in that.

Great. So, just philosophically it is not possible to go back and increase the stages on an already completed well, or is that another opportunity?

Short answer is that as a general rule, what I would say is no. We did actually, probably years ago go into a well where swell packers were already set, but the well had not been fraced, and pulled the liners and set it up a different way, but mechanically that is challenging, but our guys were able to get it done, which I was actually a bit surprised. But it is really not practical.

Okay. And my final question is just on talking about you know the pressure pumping services versus the pace at which you would like to go assuming you are able to get that additional 1 to 2 crews as we go into 2012, dedicated crews. Is there anything in your control from the point of view of pumping services that would enable you to up the pace, or is it just that you have the two additional crews, but you're still (inaudible) because sources just don’t keep up. So, you never really get the pace that you might be looking for?

I guess what I would say is that as we think about it with the next crew in the next couple of months, and then potentially another one sometime in 2012. I think that pace is sufficient for us. And so, again we try not to bounce around with respect to equipment. So we try to approach it from one direction. And so as we can line up these pressure pumping services, then we will look to add rigs.

I see. Okay. And finally, 18 wells waiting for completion versus 10 a year ago, there was some discussion earlier about if weather had not been an issue – I’m trying to understand how much of those 18 wells reflect weather versus the issue of getting services to complete the wells.

Yes, that was actually 10 wells at the end of November versus the 8 now. And as I mentioned, I would expect a typical run rate on backlog, on wells to be somewhere in – with the current rig counts to be somewhere in the 8 to 10 range. So notionally I think you can think about the weather component of the 18 being roughly 8.

Got it. Okay, so the services are not an outside issue other than just normal part of the operating challenges. Thank you so much.

Okay. Thank you.

And you have no further questions.

Great. Well, thanks for your participation in our year-end call. We will be filing our 10-K, our first 10-K as a public company in fact tomorrow. And I’m proud of what all the Oasis team has been able to do in terms of delivering the results that we will see in that 10-K that will come out tomorrow. We are pleased with our solid shareholder base, and are enjoying meeting new folks at conferences and industry events. We'll be at a number of energy conferences in the next couple of weeks and months, and look forward to catching up with many of you on the way. Thanks again.

Ladies and gentlemen, this concludes today’s conference call, you may now disconnect.